You should read the following discussion of our financial condition and results of operations in conjunction with the unaudited consolidated financial statements and notes thereto included elsewhere in this report.

As generally used in the energy industry and in this report, the following terms have the following meanings:

 /d:             Per day
 Bcf:            One billion cubic feet
 Btu:            One British thermal unit
 Lean gas        Natural gas that is low in NGL content
 MMBtu:          One million British thermal units
 Mcf:            One thousand cubic feet
 MMcf:           One million cubic feet
 NGLs:           Natural gas liquids, which consist primarily of ethane, propane,
                 isobutane, normal butane, natural gasoline and stabilized
                 condensate
 Residue gas:    The pipeline quality natural gas remaining after natural gas is
                 processed
 Rich gas        Natural gas that is high in NGL content
 Throughput:     The volume of natural gas or NGLs transported or passing through
                 a pipeline, plant, terminal or other facility

Overview

We are a Delaware limited liability company formed in 2001 to acquire entities operating under the Copano name since 1992, and to serve as a holding company for our operating subsidiaries. Through our subsidiaries, we own and operate natural gas gathering and intrastate transmission pipeline assets, natural gas processing and fractionation facilities, NGL pipelines and a crude oil pipeline. We operate in Oklahoma, Texas, Wyoming and Louisiana.

We manage our business and analyze and report our results of operations on a segment basis. Our operations are divided into three operating segments:
Oklahoma, Texas and Rocky Mountains.

• Our Oklahoma segment provides midstream natural gas services in central and east Oklahoma, including gathering and related compression, dehydration, treating and nitrogen rejection services and natural gas processing. This segment also includes a crude oil pipeline located in south Oklahoma and north Texas and our equity investment in Southern Dome.

• Our Texas segment provides midstream natural gas services in south and north Texas, including gathering and intrastate transmission of natural gas, and related services such as compression, dehydration and marketing. Our Texas segment also provides natural gas processing, conditioning and treating and NGL fractionation and transportation through our Houston Central plant and our NGL pipelines. In addition, our Texas segment includes our Saint Jo cryogenic processing plant in Montague County, Texas, and owns a processing plant located in southwest Louisiana. This segment also includes our equity investment in Webb Duval.

• Our Rocky Mountains segment provides midstream natural gas services in the Powder River Basin of Wyoming, including gathering and treating of natural gas. This segment also includes our equity investments in Bighorn and Fort Union.

Corporate and other relate to our risk management activities, intersegment eliminations and other activities we perform or assets we hold that have not been allocated to any of our reporting segments.

Trends and Uncertainties

This section, which describes recent changes in factors affecting our business, should be read in conjunction with "- How We Evaluate Our Operations" and "- How We Manage Our Operations" below. Many of the factors affecting our business are beyond our control and are difficult to predict.

Commodity Prices and Producer Activity

Our gross margins and total distributable cash flow are influenced by the prices of natural gas and NGLs, and by drilling activity. Generally, prices affect the cash flow and profitability of our Texas and Oklahoma segments directly. To the extent that they influence the level of drilling activity, commodity prices also affect all of our segments indirectly. Please read "- How We Evaluate Our Operations" and "- How We Manage Our Operations" for further discussion. For a discussion of how we use hedging to reduce the effects of commodity price fluctuations on our cash flow and profitability, please read "Item 3. Quantitative and Qualitative Disclosures About Market Risk."

The long term growth and sustainability of our business depends on natural gas prices being at levels sufficient to provide incentives, capital and adequate returns for producers to maintain and increase natural gas exploration and production. Commodity price fluctuations and access to capital influence natural gas producers as they schedule drilling projects. Low natural gas prices, particularly in combination with high operating costs, act as a disincentive to producers. In an environment of lower natural gas prices, producers typically re-evaluate their drilling schedules and related capital expenditures and, depending on the severity and duration of the pricing trends, may suspend drilling and completion of wells to the degree they have become uneconomic. We believe that future natural gas prices will be influenced by regional drilling activity and takeaway capacity, the severity of winter and summer weather, natural gas storage levels, liquefied natural gas imports, NGL transportation and fractionation capacity and the overall economy.

The ongoing recession has suppressed energy consumption and demand for consumer goods, which in turn has resulted in sharp declines in prices for oil, natural gas and NGLs compared to a year ago. Prices for oil and NGLs have begun to recover from the lows experienced in December 2008, but natural gas prices have continued to decline. Forward pricing on NYMEX reflects market expectations that oil and natural gas prices in the coming months will be consistently higher compared to recent months. However, the future of commodity prices and of the overall economy remains uncertain. If the current recession persists or deepens, the further slowdown in economic activity would likely result in continued lower natural gas prices and renewed declines in NGL prices, which in turn would delay a recovery in drilling activity.

Pricing Trends in Texas. During the second quarter of 2009, NGL prices in Texas recovered significantly from the lows experienced in the first quarter, and natural gas prices stabilized but remained near first-quarter lows. The price for natural gas on the Houston Ship Channel index was $3.22 per MMBtu for August, and month-to-date average prices for NGLs at Mount Belvieu through August 6, 2009 were $34.96 per barrel. The following graph and table summarize monthly and quarterly average prices on the primary indices we use to price natural gas and NGLs in Texas.

(1) NGLs prices for August are month-to-date through August 6, 2009. Average NGLs prices are calculated based on our weighted-average product production mix at Mt. Belvieu for the period indicated. Average NGLs prices for July and August are based on our second-quarter weighted-average production mix.

                                                                           Quarterly Data for:
                                             Q1 2008       Q2 2008       Q3 2008       Q4 2008         Q1 2009       Q2 2009
Houston Ship Channel ($/MMBtu)              $    7.73     $   10.58     $    9.98     $    6.37       $    4.21     $    3.44
Mt. Belvieu ($/barrel)                      $   58.89     $   69.22     $   68.65     $   32.50       $   25.90     $   30.19
Texas Service Throughput (MMBtu/d)            696,658       700,545       666,686       679,142         644,752       630,674
Texas Plant Inlet (MMBtu/d)                   601,736       629,334       596,225       600,719         558,115       559,597
Texas Segment Gross Margin (in thousands)   $  41,576     $  40,499     $  41,392     $  19,256       $  20,580     $  23,320

Oklahoma Prices. During the second quarter of 2009, Oklahoma NGL prices recovered modestly from the lows experienced in the first quarter, and natural gas prices stabilized but remained near first-quarter lows. The price for natural gas on CenterPoint East was $3.22 per MMBtu for August, and month-to-date average prices for NGLs at Conway through August 6, 2009 were $25.31 per barrel. The following graph and table summarize the average monthly and quarterly prices on the primary indices we use to price natural gas and NGLs in Oklahoma.

(1) NGLs prices for August are month-to-date through August 6, 2009. Average NGLs prices are calculated based on our weighted-average product production mix at Conway for the period indicated. Average NGLs prices for July and August are based on our second-quarter weighted-average production mix.

                                                                    Quarterly Data for Oklahoma
                                          Q1 2008       Q2 2008       Q3 2008       Q4 2008         Q1 2009       Q2 2009
CenterPoint East ($/MMBtu)               $    7.20     $    9.26     $    8.41     $    3.58       $    3.37     $    2.70
Conway ($/barrel)                        $   56.33     $   62.27     $   59.42     $   27.36       $   24.13     $   25.57
Oklahoma Service Throughput (MMBtu/d)      222,006       228,941       243,000       261,107         271,222       267,576
Oklahoma Plant Inlet (MMBtu/d)             150,060       155,430       158,047       160,074         160,181       166,846
Oklahoma Segment Gross Margin (in
thousands)                               $  36,570     $  47,852     $  33,536     $  18,420       $  15,071     $  18,626

For a discussion of how we use hedging to reduce the effects of commodity price fluctuations on our cash flow and profitability, please read "Item 3. Quantitative and Qualitative Disclosures About Market Risk."

Trends in Drilling and Production Activity. We experienced a modest decrease in overall volumes compared to the second quarter of 2008 largely due to lower volumes in Texas, which were attributable to a decrease in low-margin supplies from a third party pipeline and a decline in new wells from a single producer in South Texas. New drilling activity in Texas was not sufficient to offset these factors because of the weak pricing environment. Compared to the first quarter of 2009, second quarter volumes reflect modest decreases in Texas and Rocky

Mountains (including Bighorn and Fort Union), while Oklahoma volumes remained flat. These volume trends reflect a decline in drilling activity that was precipitated by sharp declines in oil and natural gas prices late in 2008.

We anticipate that producers may increase new drilling activity once natural gas prices reach a level sufficient to make drilling and production economic. The level at which drilling and production become economic depends on various factors, including the producer's drilling, completion and other operating costs, which are influenced by, among other things, the characteristics of the hydrocarbon reservoir. These costs have declined significantly since late 2008, but demand for and competing supplies of natural gas, and their anticipated effects on natural gas prices, will also influence producers' decisions regarding drilling. For producers of rich gas who share in the benefits of improved processing economics under their sales contracts, the disincentive of low natural gas prices could be offset as prices for condensate and NGLs increase. In addition, improving oil prices could lead to increased production of casinghead natural gas associated with oil production.

If the pricing environment of the second quarter of 2009 continues, we anticipate that we will see sustained or increasing drilling activity in areas that produce rich gas and declining drilling activity in areas that produce lean gas, for example, in the Rocky Mountains. We expect that many producers of lean gas will wait to see sustained increases in natural gas prices before resuming significant drilling activity. Forward pricing on NYMEX suggest that natural gas prices could improve in the near future; however, forward curves only reflect market expectations, and it is uncertain to what extent they will influence producers' drilling decisions. Once drilling activity increases, a recovery in volumes will be subject to delays for processes involved in completing and attaching new wells. Any prolonged reduction in oil and natural gas prices would further depress the current levels of exploration, development and production activity.

Other Industry Trends. Due to higher NGL prices and the completion of projects increasing NGL output, NGL fractionation facilities are experiencing capacity constraints. During the second quarter, we paid higher fees under a short term pricing arrangement for fractionation at Mt. Belvieu. If NGL production continues to increase, fees likely will also increase. If fees reach a point that renders production of ethane uneconomic, processors will have an incentive to operate in ethane-rejection mode, which could relieve capacity pressures to some extent. Ultimately, however, companies that depend on existing third-party fractionation facilities may need to seek other alternatives. We are working on an expansion of fractionation capacity at our Houston Central plant, which will allow us to sell purity ethane separately, helping to offset our increasing fractionation costs. We anticipate completing this project in early 2010.

Credit and Capital Market Disruptions. The effects of late-2008 disruptions in financial markets worldwide continue to influence the availability of debt and equity capital, although to a lesser degree. Generally, we believe that the markets have recovered moderately since the height of the financial crisis, although the cost of capital remains higher than before the financial crisis. To the extent we access financial markets in the near term, we believe that we would be able to raise debt and equity on acceptable terms, although the cost of debt and equity will depend on then-existing trading levels.

Renewed instability in the financial markets, as a result of developments in the current recession or otherwise, would have a negative impact on the cost and accessibility of capital for us, and for our customers and suppliers.

Factors Affecting Operating Results and Financial Condition

Our results for the three and six months ended June 30, 2009 reflect the lower prices and modestly lower volumes we encountered during these periods compared to the high commodity prices and increasing volumes that prevailed during the same periods in 2008. A comparison of the first and second quarters of 2009, however, reveals early signs of the benefits of strengthening NGL prices. Higher NGL prices overall combined with lower natural gas prices in Texas during the second quarter of 2009 have led to improvement in our processing margins compared to the first quarter. In addition, while our overall volumes were lower, the volume of natural gas that we processed increased slightly compared to the first quarter. As a result of the increased margins and volumes for processed gas, our combined operating segment gross margins increased 17% compared to the first quarter of 2009.

Consistent with our business strategy, we have used derivative instruments to mitigate the effects of commodity price fluctuations on our cash flow and profitability so that we can continue to meet our debt service and capital expenditure requirements, and our distribution objectives. For the three and six months ended June 30, 2009, we received $20.8 million and $45.9 million, respectively, in cash settlements from our commodity hedge

portfolio, which helped to offset the decline in operating revenues attributable to lower commodity prices. For the three and six months ended June 30, 2008, we paid $6.7 million and $12.5 million, respectively, in cash settlements to satisfy commodity swap obligations. Our results also reflect lower general and administrative and operating expenses due to our continuing cost control efforts.

How We Evaluate Our Operations

We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our performance. Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include the following: (i) throughput volumes;
(ii) segment gross margin and total segment gross margin; (iii) operations and maintenance expenses; (iv) general and administrative expenses; (v) EBITDA and adjusted EBITDA and (vi) total distributable cash flow. Segment gross margin, total segment gross margin, EBITDA, adjusted EBITDA and total distributable cash flow are non-GAAP financial measures. A reconciliation of each non-GAAP measure to its most directly comparable GAAP measure is provided below.

Throughput Volumes. Throughput volumes associated with our business are an important part of our operational analysis. We continually evaluate volumes delivered to our plants and flowing through our pipelines to ensure that we have adequate throughput to meet our financial objectives. Our performance at our processing plants is significantly influenced by the volume of natural gas delivered to the plant, the NGL content of the natural gas, the quality of the natural gas and the plant's recovery capability. In addition, we monitor fuel consumption because it has a significant impact on the gross margin realized from our processing or conditioning operations. Although we monitor fuel costs and losses associated with our pipeline operations, these costs are frequently passed on to our producers.

It is also important that we continually add new volumes to our gathering systems to offset or exceed the normal decline of existing volumes. In monitoring our pipeline volumes, managers of our Oklahoma and Texas segments evaluate what we refer to as service throughput, which consists of two components:

• the volume of natural gas transported or gathered through our pipelines, which we call pipeline throughput; and

• the volume of natural gas delivered to our wholly owned processing plants by third-party pipelines, excluding any volumes already included in our pipeline throughput.

In our Texas segment, we also compare pipeline throughput and service throughput to evaluate the volumes generated from our pipelines, as opposed to third-party pipelines. In Oklahoma, because no gas is delivered to our wholly owned plants other than by our pipelines, pipeline throughput and service throughput are equivalent.

In our Rocky Mountains segment, we evaluate producer services throughput, which we define as volumes we purchased for resale, volumes gathered using our firm capacity gathering agreements with Fort Union and volumes transported using our firm transportation agreements with WIC, or using additional capacity that we obtain on WIC. We also regularly assess the pipeline throughput of Bighorn and Fort Union.

Segment Gross Margin and Total Segment Gross Margin. We define segment gross margin as an operating segment's revenue minus cost of sales. Cost of sales includes the following: cost of natural gas and NGLs we purchase, cost of crude oil we purchase and costs for transportation of our volumes. We view segment gross margin as an important performance measure of the core profitability of our operations. Segment gross margin allows our senior management to compare volume and price performance of our segments and to more easily identify operational or other issues within a segment. With respect to our Oklahoma and Texas segments, our management analyzes segment gross margin per unit of service throughput. With respect to our Rocky Mountains segment, our management analyzes segment gross margin per unit of producer services throughput. Also, our management analyzes the cash distributions our Rocky Mountains segment receives from Bighorn and Fort Union.

Our Oklahoma margins are, on the whole, positively correlated with NGL prices and natural gas prices. In Texas, increases in natural gas prices or decreases in NGL prices generally have a negative impact on margins, and, conversely, a reduction in natural gas prices or an increase in NGL prices generally has a positive impact. However, when we operate our Houston Central plant in conditioning mode, increases in natural gas prices have a positive impact on our margins. The profitability of our Rocky Mountains operations is not directly affected by commodity

prices. Substantially all of our Rocky Mountains contract portfolio, as well as Bighorn's and Fort Union's contract portfolios, consist of fixed-fee arrangements providing for an agreed gathering fee per unit of natural gas throughput. Our revenues from these arrangements are directly related to the volume of natural gas that flows through these systems and is not directly affected by commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, however, our revenues under these arrangements would also decline.

To measure the overall financial impact of our contract portfolio, we use total segment gross margin, which is the sum of our operating segments' gross margins and the results of our risk management activities, which are included in corporate and other. Our total segment gross margin is determined primarily by five interrelated variables: (i) the volume of natural gas gathered or transported through our pipelines, (ii) the volume of natural gas processed, conditioned, fractionated or treated at our processing plants or on our behalf at third-party processing plants, (iii) natural gas and NGL prices and the relative price differential between NGLs and natural gas, (iv) our contract portfolio and (v) the results of our risk management activities. The results of our risk management activities consist of (i) net cash settlements paid or received on expired commodity derivative instruments, (ii) amortization expense relating to the option component of our commodity derivative instruments and
(iii) unrealized mark-to-market gain or loss on our commodity derivative instruments that have not been designated as cash flow hedges.

Because our profitability is a function of the difference between the revenues we receive from our operations, including revenues from the products we sell, and the costs associated with conducting our operations, including the costs of products we purchase, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. To a large extent, our contract portfolio and the pricing environment for natural gas and NGLs will dictate increases or decreases in our profitability. Our profitability is also dependent upon the market demand for natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors.

Both segment gross margin and total segment gross margin are reviewed monthly for consistency and trend analysis.

Operations and Maintenance Expenses. The most significant portion of our operations and maintenance expenses consists of direct labor, insurance, repair and maintenance, utilities and contract services. These expenses remain relatively stable across broad volume ranges and fluctuate slightly depending on the activities performed during a specific period. A portion of our operations and maintenance expenses is incurred through Copano Operations, an affiliate of our company controlled by John R. Eckel, Jr., the Chairman of our Board of Directors and our Chief Executive Officer. See Note 8 of the notes to the unaudited consolidated financial statements included in Item 1 of this report. Under the terms of our arrangement with Copano Operations, we have agreed to reimburse it, at cost, for the operations and maintenance expenses it incurs on our behalf, which consist primarily of payroll costs. We monitor operations and maintenance expenses to assess the impact of such costs on the profitability of a particular asset or group of assets and to evaluate the efficiency of our operations.

General and Administrative Expenses. Our general and administrative expenses include the cost of employee and officer compensation and related benefits, office lease and expenses, professional fees, information technology expenses, as well as other expenses not directly associated with our field operations. A portion of our general and administrative expenses are incurred through Copano Operations, an affiliate of our company. See Note 8 of the notes to the unaudited consolidated financial statements included in Item 1 of this report. Under the terms of our arrangement with Copano Operations, we have agreed to reimburse it, at cost, for the general and administrative expenses it incurs on our behalf. To help ensure the appropriateness of our general and administrative expenses, we monitor such expenses through comparison with general and administrative expenses incurred by similar midstream companies and with the annual financial plan approved by our Board of Directors.

EBITDA and Adjusted EBITDA. We define EBITDA as net income (loss) plus interest and other financing costs, provision for income taxes and depreciation, amortization and impairment expense. Because a portion of our net income (loss) is attributable to equity in earnings (loss) from our equity investees (which include Bighorn, Fort Union, Webb Duval and Southern Dome), our management also calculates adjusted EBITDA to reflect the depreciation, amortization and impairment expense and interest and other financing costs embedded in the equity in earnings (loss) from unconsolidated affiliates. Specifically, our management determines adjusted EBITDA by

adding to EBITDA (i) the amortization expense attributable to the difference between our carried investment in each unconsolidated affiliate and the underlying equity in its net assets, (ii) the portion of each unconsolidated affiliate's depreciation and amortization expense which is proportional to our ownership interest in that unconsolidated affiliate and (iii) the portion of each unconsolidated affiliate's interest and other financing costs which is proportional to our ownership interest in that unconsolidated affiliate.

External users of our financial statements such as investors, commercial banks and research analysts use EBITDA or adjusted EBITDA, and our management uses adjusted EBITDA, as a supplemental financial measure to assess:

• the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

• the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;

• our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and

• the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

EBITDA is also a financial measure that, with certain negotiated adjustments, is . . .